1. Field of the Invention
The present application relates generally to the exploration of hydrocarbon reservoirs, and more particularly to methodology and supporting systems for managing business decisions on where and how to explore for hydrocarbon reservoirs.
2. State of the Art
Oil and gas exploration and production (E & P) companies create value for their owners or shareholders by exploiting hydrocarbon accumulations for commercial gain. To maintain owner/shareholder value, they must replace reserves (their asset base) whilst maintaining production rates (their revenue stream). Other entities, such as state-owned national oil companies and the like, also exploit hydrocarbon accumulations for commercial gain and most often have a desire to replace reserves. Reserves can be replaced through exploration, improving existing field recovery factors, and acquisition of existing discoveries or fields.
For new ventures, the exploration process typically begins with a high level analysis of known field size distribution and economic attractiveness of the exploitation of hydrocarbons in any county throughout the world. The right to explore for hydrocarbons in a country is typically granted by a government licensing body for considerable sums of money, a technical work program (commitment), or both. The work program will typically depend on how much work has previously been done and how much technical insight with respect to the area is known in advance of the award. Work programs are usually limited in time and may require the licensee to perform activities by certain dates, e.g., to acquire seismic data and/or drill exploratory wells to attempt to establish the location of economically producible hydrocarbon accumulations.
For the licensee, there is a strong incentive to execute the exploration process as quickly and effectively as possible due to the fact that:                the license may expire before a commercial discovery is made; and        in net present value (NPV) terms, no commercial valuation is positively impacted until additional reserves can be booked as a result of the exploration process.        
In offshore areas, exploration costs may be very high. Onshore is usually less expensive for drilling, but 3D seismic data acquisition may be more expensive than offshore. Very few areas of the world have not already had at least one phase of exploration. The whereabouts of most sedimentary basins is known. Most commonly, companies enter a known basin or area with new ideas and/or technology. Not all countries release pre-existing well and seismic data prior to license award.
The exploration for hydrocarbons in any area varies depending on what is known or what work has been done in advance. Prior knowledge and work results help companies understand uncertainty and the probability of finding hydrocarbons. Managing uncertainty and risk are vital components of successful exploration.
For E&P companies, the exploration process typically involves the following. First, in order to gain access to a basin or part thereof, the company first pays for a license to explore. The company then assimilates existing data (such as well logs from previously drilled wells) or previously acquired geophysical data (such as seismic or magnetic surveys). The company may then need to reprocess this existing data or collect new data such as surface geochemical samples or seismic data in order to determine which parts of the licensed acreage are most prospective. Petrophysical analysis of wells and rock samples for reservoir properties and source rock potential is often undertaken in parallel. If promising geological structures (referred to as “leads”) are identified, it may be necessary to acquire more densely sampled seismic data or electromagnetic data to try to increase the probability that a given subsurface structure (a “prospect”) is charged with hydrocarbons. In the exploration process, there is a delicate balance to be struck between time and cost of work to understand uncertainty and the probability of mitigating risk.
For economic hydrocarbons to be encountered in any prospect, the following technical conditions must simultaneously be met:                1) a valid trap is present to retain the hydrocarbons at high saturations in sufficient quantities as to be commercially viable,        2) a reservoir formation is present that has sufficient porosity to store mobile hydrocarbons and sufficient permeability to allow them to flow into a wellbore at commercial rates,        3) after its formation (timing) the trap needs to have received a hydrocarbon charge from        4) mature source rocks with accessible migration pathways.        5) The trap must also have retained the charge due to the presence of a seal, impermeable vertical and horizontal barriers, lithology and faults etc. that prevent the hydrocarbons from escaping.        
Work by geoscientists as part of the exploration process aims to establish the likelihood that these conditions have been met, i.e., the probability of success. This is usually achieved by integrating geophysical measurements and geological inference from outcrops, surface samples or analogue accumulations. Additional data and information helps to reinforce estimates of the likelihood of a positive or negative outcome.
When an E&P company or other entity is sufficiently confident that all these criteria may have been met at a given location in the subsurface and the accumulation is estimated to be large enough to be commercially attractive, the prospect may be drilled. Only once a prospect has been drilled and tested (and possibly appraised by other wells) may the reserves be booked, and thus increase the asset base and net worth of the company or entity. The process of moving from having acquired an exploration license to drilling a well to test a prospect may take hundreds of millions of dollars and several years. In this time period, the exploration activities represent negative cash flow and no added value to the company until a discovery is established by drilling a well that discovers a commercially viable hydrocarbon accumulation.
From the foregoing it is clear that E&P companies and other entities are strongly motivated to accelerate the exploration process as much as possible, whilst working at the same time to understand uncertainty and manage the risk that this acceleration, and any consequential lack of work, does not lead to drilling a prospect that does not contain commercial quantities of hydrocarbons. It should also be understood that hydrocarbon exploration involves taking calculated, but inherent, risk and that it is usually not possible to completely eliminate the possibility of drilling a prospect that does not contain commercial quantities of hydrocarbons, particularly in a cost effective manner.
In an ideal case, an E&P company or other entity should spend no more than necessary to delineate the prospect in the shortest amount of time such that an exploration well may be safely and successfully drilled to establish the presence of a commercial hydrocarbon accumulation. In practice, this goal is not met because of a variety of issues, which can include one or more of the following:                Difficulty of efficiently assimilating the existing data,        Inefficiencies in constructing basin-scale charge and play models from the data,        Acquisition of additional data and processing,        Updating of basin-scale play fairway models with new information,        Definition of the prospect: trap, reservoir, seal, migration and timing,        Evaluation of uncertainties, probabilities, risks and economics,        Construction of exploration well design and operation programs,        Contracting of drilling rig, and        Drilling and evaluating the first exploration well on the prospect.        
Previous technologies have typically aimed at improving the efficiency of various elements of this exploration process. SPE 84337, for instance, discloses a method to capture uncertainties as part of decision tree analysis and Monte Carlo simulation. The decision tree had two branches. The first branch consisted of volume related events (Remaining Gas Reserves, Remaining Oil Reserves, Gas Gap Volume) and gave an idea of the amount of gas in a reservoir. The second branch consisted of performance related events (Average Oil Production Rate per Reservoir Pressure Change, Average Gas Production Rate per Reservoir Pressure Change, Flow Capacity, Oil Storage Capacity, and Distance to gas pipelines) and gave an idea of how much gas could be reasonably produced from the reservoir. The data for each event were normalized (0-1) and a swing weighting method used to calculate probabilities of occurrence of each event. These probabilities were designated as assumption cells with the probability density functions based on best-fit curves. A rolling netback calculation was carried out with normalized values of the events and their respective forecasted probabilities of occurrences until a final rank score was obtained.